In wellbore construction and completion operations, a wellbore is initially formed to access hydrocarbon-bearing formations (i.e., crude oil and/or natural gas) by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a tubular string, commonly known as a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annular area is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. A cementing operation is then conducted in order to fill the annular area with cement. Using apparatus known in the art, the casing string is cemented into the wellbore by circulating cement into the annular area defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
A drilling rig is constructed on the earth's surface to facilitate the insertion and removal of tubular strings (i.e., drill strings or casing strings) into a wellbore. Alternatively, the drilling rig may be disposed on a jack-up platform, semi-submersible platform, or a drillship for drilling a subsea wellbore. The drilling rig includes a platform and power tools such as a top drive and a spider to engage, assemble, and lower the tubulars into the wellbore. The top drive is suspended above the platform by a draw works that can raise or lower the top drive in relation to the floor of the rig. The spider is mounted in the platform floor. The top drive and spider are designed to work in tandem. Generally, the spider holds a tubular or tubular string that extends into the wellbore from the platform. The top drive engages a new tubular and aligns it over the tubular being held by the spider. The top drive is then used to thread the upper and lower tubulars together. Once the tubulars are joined, the spider disengages the tubular string and the top drive lowers the tubular string through the spider until the top drive and spider are at a predetermined distance from each other. The spider then re-engages the tubular string and the top drive disengages the string and repeats the process. This sequence applies to assembling tubulars for the purpose of drilling, running casing or running wellbore components into the well. The sequence can be reversed to disassemble the tubular string.
Top drives are used to rotate a drill string to form a borehole. Top drives are equipped with a motor to provide torque for rotating the drilling string. The quill or drive shaft of the top drive is typically threadedly connected to an upper end of the drill pipe in order to transmit torque to the drill pipe. Top drives may also be used to make up casing for lining the borehole. To make-up casing, existing top drives use a threaded crossover adapter to connect to the casing. This is because the quill of the top drives is typically not sized to connect with the threads of the casing. The crossover adapter is design to alleviate this problem. Generally, one end of the crossover adapter is designed to connect with the quill, while the other end is designed to connect with the casing. In this respect, the top drive may be adapted to retain a casing using a threaded connection. However, the process of connecting and disconnecting a casing using a threaded connection is time consuming. For example, each time a new casing is added, the casing string must be disconnected from the crossover adapter. Thereafter, the crossover must be threaded to the new casing before the casing string may be run. Furthermore, the threading process also increases the likelihood of damage to the threads, thereby increasing the potential for downtime.
As an alternative to the threaded connection, top drives may be equipped with tubular gripping heads to facilitate the exchange of wellbore tubulars such as casing or drill pipe. Generally, tubular gripping heads have an adapter for connection to the quill of top drive and gripping members for gripping the wellbore tubular. Tubular gripping heads include an external gripping device, such as a torque head, or an internal gripping device, such as a spear.
FIG. 1A is a side view of an upper portion of a drilling rig 10 having a top drive 100 and an elevator assembly 35. The elevator assembly 35 may include a piston and cylinder assembly (PCA) 35a, a bail 35b, and an elevator 35c. An upper end of a stand of casing joints 70 is shown on the rig 10. The elevator assembly 35 is engaged with one of the stands 70. The stand 70 is placed in position below the top drive 100 by the elevator assembly 35 in order for the top drive having a gripping head, such as a spear 190, to engage the tubular.
FIG. 1B is a side view of a drilling rig 10 having a top drive 100, an elevator assembly 35, and a spider 60. The rig 10 is built at the surface 45 of the wellbore 50. The rig 10 includes a traveling block 20 that is suspended by wires 25 from draw works 15 and holds the top drive 100. The top drive 100 has the spear 190 for engaging the inner wall of the casing 70 and a motor 140 to rotate the casing 70. The motor 140 may be either electrically or hydraulically driven. The motor 140 rotates and threads the casing 70 into the casing string 80 extending into the wellbore 50. Additionally, the top drive 100 is shown having a railing system 30 coupled thereto. The railing system 30 prevents the top drive 100 from rotational movement during rotation of the casing 70, but allows for vertical movement of the top drive under the traveling block 110. The top drive 100 is shown engaged to casing 70. The casing 70 is positioned above the casing string 80 located therebelow. With the casing 70 positioned over the casing string 80, the top drive 100 can lower casing 70 into the casing string 80. Additionally, the spider 60, disposed in a platform 40 of the drilling rig 10, is shown engaged around the casing string 80 that extends into wellbore 50.
FIG. 1C illustrates a side view of the top drive 100 engaged to the casing 70, which has been connected to the casing string 80 and lowered through the spider 60. The elevator assembly 35 and the top drive 100 are connected to the traveling block 20 via a compensator 170. The compensator 170 functions similar to a spring to compensate for vertical movement of the top drive 100 during threading of the casing 70 to the casing string 80. FIG. 1C also illustrates the spider 60 disposed in the platform 40. The spider 60 comprises a slip assembly 66, including a set of slips 62, and piston 64. The slips 62 are wedge-shaped and are constructed and arranged to slide along a sloped inner wall of the slip assembly 66. The slips 62 are raised or lowered by piston 64. When the slips 62 are in the lowered position, they close around the outer surface of the casing string 80. The weight of the casing string 80 and the resulting friction between the tubular string 80 and the slips 62, force the slips downward and inward, thereby tightening the grip on the casing string. When the slips 62 are in the raised position as shown, the slips are opened and the casing string 80 is free to move longitudinally in relation to the slips.
A typical operation of a adding a casing joint or stand of joints to a casing string using a top drive and a spider is as follows. A tubular string 80 is retained in a closed spider 60 and is thereby prevented from moving in a downward direction. The top drive 100 is then moved to engage the casing joint/stand 70 from a stack with the aid of the elevator assembly 35. Engagement of the casing 70 by the top drive 100 includes grasping the casing and engaging the inner (or outer) surface thereof. The top drive 100 then moves the casing 70 into position above the casing string 80. The top drive 100 then threads the casing 70 to casing string 80. The spider 60 is then opened and disengages the casing string 80. The top drive 100 then lowers the casing string 80, including casing 70, through the opened spider 60. The spider 60 is then closed around the tubular string 80. The top drive 100 then disengages the tubular string 80 and can proceed to add another joint/stand of casing 70 to the casing string 80.
The adapter of the tubular gripping head (i.e. spear 190) connects to the quill of the top drive using a threaded connection. The adapter may be connected to the quill either directly or indirectly, e.g., through another component such as a sacrificial saver sub. One problem that may occur with the threaded connection is inadvertent breakout of that connection during operation. For example, a casing connection may be required to be backed out (i.e., unthreaded) to correct an unacceptable makeup. It may be possible that the left hand torque required to break out the casing connection exceeds the breakout torque of the connection between the adapter and the quill, thereby inadvertently disconnecting the adapter from the quill and creating a hazardous situation on the rig. There is a need, therefore, for methods and apparatus for ensuring safe operation of a top drive.
Further, each joint of conventional casing has an internal threading at one end and an external threading at another end. The externally-threaded end of one length of tubing is adapted to engage in the internally-threaded end of another length of tubing. These connections between lengths of casing rely on thread interference and the interposition of a thread compound to provide a seal.
As the petroleum industry has drilled deeper into the earth during exploration and production, increasing pressures have been encountered. In such environments, it may be beneficial to employ premium grade casing joints which include a metal-to-metal sealing area or engaged shoulders in addition to the threads. It would be advantageous to employ top drives in the make-up of premium casing joints. Current measurements are obtained by measuring the voltage and current of the electricity supplied to an electric motor or the pressure and flow rate of fluid supplied to a hydraulic motor. Torque is then calculated from these measurements. This principle of operation neglects friction inside a transmission gear of the top drive and inertia of the top drive, which are substantial. Therefore, there exists a need in the art for a more accurate top drive torque measurement.